Oil & Gas Wells
In the context of production from a well, oil and gas are understood to refer to crude oil and natural gas. Oil and gas are naturally occurring hydrocarbons in certain subterranean formations.
A subterranean formation containing oil or gas may be located under land or under the seabed off shore. Oil and gas reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs) below the surface of the land or seabed.
There are conventional and non-conventional types of reservoirs. In a conventional reservoir, the hydrocarbons flow to the wellbore in a manner that can be characterized by flow through permeable media, where the permeability may or may not have been altered near the wellbore, or flow through permeable media to a permeable (conductive), bi-wing fracture placed in the formation. A conventional reservoir would typically have a matrix permeability greater than about 1 milliDarcy (equivalent to about 1,000 microDarcy). In a non-conventional reservoir, the permeability is less than 1 milliDarcy. Non-conventional reservoirs include tight gas, shale, and coal bed methane.
To produce oil or gas, a well is drilled into a subterranean formation that is an oil or gas reservoir. Generally, the greater the depth of the formation, the higher the bottomhole static temperature and pressure of the formation.
A wellbore can be used as a production or injection wellbore. A production wellbore is used to produce hydrocarbons from the reservoir. An injection wellbore is used to inject a fluid, e.g., liquid water or steam, to drive oil or gas to a production wellbore.
Well Servicing and Well Fluids
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation.
Well services can include various types of treatments that are commonly performed in a wellbore or subterranean formation. For example, during completion or intervention, stimulation is a type of treatment performed to enhance or restore the productivity of oil and gas from a well. Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Matrix treatments are performed below the fracture pressure of the formation. Other types of completion or intervention treatments can include, for example, gravel packing, consolidation, and controlling excessive water production, and controlling sand or fines production. Still other types of completion or intervention treatments include, but are not limited to, damage removal, formation isolation, wellbore cleanout, scale removal, and scale control. Of course, other well treatments and treatment fluids are known in the art.
Hydraulic Fracturing
Hydraulic fracturing is a common stimulation treatment. The purpose of a fracturing treatment is to provide an improved flow path for oil or gas to flow from the hydrocarbon-bearing formation to the wellbore. A treatment fluid adapted for this purpose is sometimes referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance one or more fractures in the subterranean formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture in the formation.
The formation or extension of a fracture in hydraulic fracturing may initially occur suddenly. When this happens, the fracturing fluid suddenly has a fluid flow path through the fracture to flow more rapidly away from the wellbore. As soon as the fracture is created or enhanced, the sudden increase in the flow of fluid away from the well reduces the pressure in the well. Thus, the creation or enhancement of a fracture in the formation may be indicated by a sudden drop in fluid pressure, which may be observable at the wellhead. After initially breaking down the formation, the fracture may then propagate more slowly, at the same pressure or with little pressure increase. It can also be detected with seismic techniques.
A newly-created or newly-extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material is usually placed in the fracture to keep the fracture propped open and to provide higher fluid conductivity than the matrix of the formation. A material used for this purpose is referred to as a proppant.
A proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture to form a proppant pack. The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the matrix of the surrounding subterranean formation. This higher-permeability flow path increases oil and gas production from the subterranean formation.
A particulate for use as a proppant is usually selected based on the characteristics of size range, crush strength, and solid stability in the types of fluids that are encountered or used in wells. Preferably, a proppant should not melt, dissolve, or otherwise degrade from the solid state under the downhole conditions.
The proppant is selected to be an appropriate size to prop open the fracture and bridge the fracture width expected to be created by the fracturing conditions and the fracturing fluid. If the proppant is too large, it will not easily pass into a fracture and will screenout too early. If the proppant is too small, it will not provide the fluid conductivity to enhance production. See, for example, McGuire and Sikora, 1960. In the case of fracturing relatively permeable or even tight-gas reservoirs, a proppant pack should provide higher permeability than the matrix of the formation. In the case of fracturing ultra-low permeable formations, such as shale formations, a proppant pack should provide for higher permeability than the naturally occurring fractures or other micro-fractures of the fracture complexity.
Appropriate sizes of particulate for use as a proppant are typically in the range from about 8 to about 100 U.S. Standard Mesh. A typical proppant is sand-sized, which geologically is defined as having a largest dimension ranging from about 0.06 millimeters up to about 2 millimeters (mm). (The next smaller particle size class below sand sized is silt, which is defined as having a largest dimension ranging from less than about 0.06 mm down to about 0.004 mm.) As used herein, proppant does not mean or refer to suspended solids, silt, fines, or other types of insoluble solid particulate smaller than about 0.06 mm (about 230 U.S. Standard Mesh). Further, it does not mean or refer to particulates larger than about 3 mm (about 7 U.S. Standard Mesh).
The proppant is sufficiently strong, that is, has a sufficient compressive or crush resistance, to prop the fracture open without being deformed or crushed by the closure stress of the fracture in the subterranean formation. For example, for a proppant material that crushes under closure stress, a 20/40 mesh proppant preferably has an API crush strength of at least 4,000 psi closure stress based on 10% crush fines according to procedure API RP-56. A 12/20 mesh proppant material preferably has an API crush strength of at least 4,000 psi closure stress based on 16% crush fines according to procedure API RP-56. This performance is that of a medium crush-strength proppant, whereas a very high crush-strength proppant would have a crush-strength of about 10,000 psi. In comparison, for example, a 100-mesh proppant material for use in an ultra-low permeable formation such as shale preferably has an API crush strength of at least 5,000 psi closure stress based on 6% crush fines. The higher the closing pressure of the formation of the fracturing application, the higher the strength of proppant is needed. The closure stress depends on a number of factors known in the art, including the depth of the formation.
Further, a suitable proppant should be stable over time and not dissolve in fluids commonly encountered in a well environment. Preferably, a proppant material is selected that will not dissolve in water or crude oil.
Suitable proppant materials include, but are not limited to, sand (silica), ground nut shells or fruit pits, sintered bauxite, glass, plastics, ceramic materials, processed wood, resin coated sand or ground nut shells or fruit pits or other composites, and any combination of the foregoing. Mixtures of different kinds or sizes of proppant can be used as well. In conventional reservoirs, if sand is used, it commonly has a median size anywhere within the range of about 20 to about 100 U.S. Standard Mesh. For a synthetic proppant, it commonly has a median size anywhere within the range of about 8 to about 100 U.S. Standard Mesh.
The concentration of proppant in the treatment fluid depends on the nature of the subterranean formation. As the nature of subterranean formations differs widely, the concentration of proppant in the treatment fluid may be in the range of from about 0.03 kilograms to about 12 kilograms of proppant per liter of liquid phase (from about 0.1 lb/gal to about 25 lb/gal).
Carrier Fluid for Particulate
A well fluid can be adapted to be a carrier fluid for particulates.
For example, a proppant used in fracturing or a gravel used in gravel packing may have a much different density than the carrier fluid. For example, sand has a specific gravity of about 2.7, whereas water has a specific gravity of 1.0 at Standard Laboratory conditions of temperature and pressure. A proppant or gravel having a different density than water will tend to separate from water very rapidly.
As many well fluids are water-based, partly for the purpose of helping to suspend particulate of higher density, and for other reasons known in the art, the density of the fluid used in a well can be increased by including highly water-soluble salts in the water, such as potassium chloride. However, increasing the density of a well fluid will rarely be sufficient to match the density of the particulate.
Increasing Viscosity of Fluid for Suspending Particulate
Increasing the viscosity of a well fluid can help prevent a particulate having a different specific gravity than an external phase of the fluid from quickly separating out of the external phase.
A viscosity-increasing agent can be used to increase the ability of a fluid to suspend and carry a particulate material in a well fluid. A viscosity-increasing agent can be used for other purposes, such as matrix diversion, conformance control, or friction reduction.
A viscosity-increasing agent is sometimes referred to in the art as a viscosifying agent, viscosifier, thickener, gelling agent, or suspending agent. In general, any of these refers to an agent that includes at least the characteristic of increasing the viscosity of a fluid in which it is dispersed or dissolved. There are several kinds of viscosity-increasing agents and related techniques for increasing the viscosity of a fluid.
In general, because of the high volume of fracturing fluid typically used in a fracturing operation, it is desirable to efficiently increase the viscosity of fracturing fluids to the desired viscosity using as little viscosity-increasing agent as possible. In addition, relatively inexpensive materials are preferred. Being able to use only a small concentration of the viscosity-increasing agent requires a lesser amount of the viscosity-increasing agent in order to achieve the desired fluid viscosity in a large volume of fracturing fluid.
Polymers for Increasing Viscosity
Certain kinds of polymers can be used to increase the viscosity of a fluid. In general, the purpose of using a polymer is to increase the ability of the fluid to suspend and carry a particulate material. Polymers for increasing the viscosity of a fluid are preferably soluble in the external phase of a fluid. Polymers for increasing the viscosity of a fluid can be naturally occurring polymers such as polysaccharides, derivatives of naturally occurring polymers, or synthetic polymers.
Treatment fluids used in high volumes, such as fracturing fluids, are usually water-based. Efficient and inexpensive viscosity-increasing agents for water include certain classes of water-soluble polymers.
As will be appreciated by a person of skill in the art, the dispersibility or solubility in water of a certain kind of polymeric material may be dependent on the salinity or pH of the water. Accordingly, the salinity or pH of the water can be modified to facilitate the dispersibility or solubility of the water-soluble polymer. In some cases, the water-soluble polymer can be mixed with a surfactant to facilitate its dispersibility or solubility in the water or salt solution utilized.
The water-soluble polymer can have an average molecular weight in the range of from about 50,000 to 20,000,000, most preferably from about 100,000 to about 4,000,000. For example, guar polymer is believed to have a molecular weight in the range of about 2 to about 4 million.
Typical water-soluble polymers used in well treatments include water-soluble polysaccharides and water-soluble synthetic polymers (e.g., polyacrylamide). The most common water-soluble polysaccharides employed in well treatments are guar and its derivatives.
As used herein, a “polysaccharide” can broadly include a modified or derivative polysaccharide. As used herein, “modified” or “derivative” means a compound or substance formed by a chemical process from a parent compound or substance, wherein the chemical skeleton of the parent is retained in the derivative. The chemical process preferably includes at most a few chemical reaction steps, and more preferably only one or two chemical reaction steps. As used herein, a “chemical reaction step” is a chemical reaction between two chemical reactant species to produce at least one chemically different species from the reactants (regardless of the number of transient chemical species that may be formed during the reaction). An example of a chemical step is a substitution reaction. Substitution on a polymeric material may be partial or complete.
A polymer can be classified as being single chain or multi chain, based on its solution structure in aqueous liquid media. Examples of single-chain polysaccharides that are commonly used in the oilfield industry include guar, guar derivatives, and cellulose derivatives. Guar polymer, which is derived from the beans of a guar plant, is referred to chemically as a galactomannan gum. Examples of multi-chain polysaccharides include xanthan, diutan, and scleroglucan, and derivatives of any of these. Without being limited by any theory, it is currently believed that the multi-chain polysaccharides have a solution structure similar to a helix or are otherwise intertwined.
Xanthan gum (commonly referred to simply as xanthan) is a polysaccharide, derived from the bacterial coat of Xanthomonas campestris. It is produced by fermentation of glucose, sucrose, or lactose by the Xanthomonas campestris bacterium. After a fermentation period, the polysaccharide is precipitated from a growth medium with isopropyl alcohol, dried, and ground into a fine powder. Later, it is added to a liquid medium to form the gum.
As used herein, the term “clarified xanthan” refers to a xanthan that has a flow rate of at least about 200 ml in 2 minutes at ambient temperature in a filtering laboratory test on a Baroid Filter Press using 40 psi of differential pressure and a 9 cm Whatman No. 4 filter paper having a 2.7 micrometer pore size. In some cases, clarified xanthans may have been obtained by treating xanthan with methods involving enzymes or any other suitable method, inter alia, to remove any debris, for example, residual cellular structures, such as cell walls, from a non-clarified, standard xanthan. Clarified xanthans can be obtained by genetic engineering or bacteria selection. In still other cases, the clarified xanthan may be obtained by chemical treatment or derivatization of a xanthan. An example of such a modification would be an oxidized or hydrolyzed xanthan.
Diutan gum (commonly referred to simply as diutan) is a multi-chain polysaccharide that is sometimes used to increase viscosity in well fluids. In general, diutan is a polysaccharide which may be prepared by fermentation of a strain of sphingomonas.
The term “clarified diutan” as used herein refers to a diutan that has improved turbidity or filtration properties as compared to non-clarified diutan. In some embodiments, suitable clarified diutans may have been treated with enzymes or the like to remove residual cellular structures, such as cell walls. In some embodiments, suitable clarified diutans may be produced from genetically modified or bioengineered strains of bacteria or other strains of bacteria that allow the clarified diutan to have improved functional properties such as filterability, turbidity, etc.
A fluid viscosified with a diutan or derivatized diutan can enable a substantial amount of design flexibility for a number of applications that would benefit using a shear-thinning, low-damage fluid system including, for example, gravel packing, fluid-loss control, and friction pressure reduction.
A fluid viscosified with a diutan or derivatized diutan can enable a simple mixing procedure and rapid viscosity development in a number of water-based fluids including for example, fresh water, potassium or sodium chloride brines, and sodium bromide brines. The polymer can be rapidly dispersed in an aqueous phase without going through a complex mixing protocol or an extended hydration period. Its ease of mixing and rapid hydration apply to seawater and mono-valent brines used in completion operations.
Diutan viscosified fluid can provide excellent particulate suspension under static conditions at temperatures up to 270° F. (132.2° C.). It is a shear thinning fluid having relatively low viscosity at high shear rates and high viscosity at low shear rates.
Because such fluids have high viscosity under low shear conditions, it can be useful to suspend particulates similar to a fluid viscosified with a cross-linked polymer. In addition, the high viscosities under low shear attained with these polymer loadings can be used to help control fluid losses during workover and completion operations with reduced damage to the formation.
The viscosity-increasing agent can be provided in any form that is suitable for the particular treatment fluid or application. For example, the viscosity-increasing agent can be provided as a liquid, gel, suspension, or solid additive that is admixed or incorporated into a treatment fluid.
The viscosity-increasing agent should be present in a treatment fluid in a form and in an amount at least sufficient to impart the desired viscosity to a treatment fluid. For example, the amount of viscosity-increasing agent used in the treatment fluids may vary from about 0.25 pounds per 1,000 gallons of treatment fluid (“lbs/Mgal”) to about 200 lbs/Mgal. In other embodiments, the amount of viscosity-increasing agent included in the treatment fluids may vary from about 10 lbs/Mgal to about 80 lbs/Mgal. In another embodiment, about 20 pounds to about 70 pounds (lbs) of water-soluble polymer per 1,000 gallons (Mgal) of water (equivalent to about 2.4 g/L to about 8.4 g/L).
Crosslinking of Polymer to Increase Viscosity of a Fluid or Form a Gel
The viscosity of a fluid at a given concentration of viscosity-increasing agent can be greatly increased by crosslinking the viscosity-increasing agent. A crosslinking agent, sometimes referred to as a crosslinker, can be used for this purpose. A crosslinker interacts with at least two polymer molecules to form a “crosslink” between them.
If crosslinked to a sufficient extent, the polysaccharide may form a gel with water. Gel formation is based on a number of factors including the particular polymer and concentration thereof, the particular crosslinker and concentration thereof, the degree of crosslinking, temperature, and a variety of other factors known to those of ordinary skill in the art.
Sometimes, however, crosslinking is undesirable, as it may cause the polymeric material to be more difficult to break and it may leave an undesirable residue in the formation.
Viscosifying Surfactants (i.e. Viscoelastic Surfactants)
It should be understood that merely increasing the viscosity of a fluid may only slow the settling or separation of distinct phases and does not necessarily stabilize the suspension of any particles in the fluid.
Certain viscosity-increasing agents can also help suspend a particulate material by increasing the elastic modulus of the fluid. The elastic modulus is the measure of a substance's tendency to be deformed non-permanently when a force is applied to it. The elastic modulus of a fluid, commonly referred to as G′, is a mathematical expression and defined as the slope of a stress versus strain curve in the elastic deformation region. G′ is expressed in units of pressure, for example, Pa (Pascals) or dynes/cm2. As a point of reference, the elastic modulus of water is negligible and considered to be zero.
An example of a viscosity-increasing agent that is also capable of increasing the suspending capacity of a fluid is to use a viscoelastic surfactant. As used herein, the term “viscoelastic surfactant” refers to a surfactant that imparts or is capable of imparting viscoelastic behavior to a fluid due, at least in part, to the association of surfactant molecules to form viscosifying micelles.
Viscoelastic surfactants may be cationic, anionic, or amphoteric in nature. The viscoelastic surfactants can comprise any number of different compounds, including methyl ester sulfonates, hydrolyzed keratin, sulfosuccinates, taurates, amine oxides, ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols (e.g., lauryl alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fatty amines, ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate), betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropyl betaine), quaternary ammonium compounds (e.g., trimethyltallowammonium chloride, trimethylcocoammonium chloride), derivatives thereof, and combinations thereof.
Matrix Diversion
Matrix treatments in conventional reservoirs can utilize matrix diversion. For example, in subterranean treatments in conventional reservoirs, it is often desired to treat an interval of a subterranean formation having sections of varying permeability, reservoir pressures or varying degrees of formation damage, and thus may accept varying amounts of certain treatment fluids. For example, low reservoir pressure in certain areas of a subterranean formation or a rock matrix or a proppant pack of high permeability may permit that portion to accept larger amounts of certain treatment fluids. It may be difficult to obtain a uniform distribution of the treatment fluid throughout the entire interval. For instance, the treatment fluid may preferentially enter portions of the interval with low fluid flow resistance at the expense of portions of the interval with higher fluid flow resistance. In some instances, these intervals with variable flow resistance may be water-producing intervals.
Fluid-Loss Control
Fluid loss refers to the undesirable leakage of a fluid phase of any type of well fluid into the permeable matrix of a zone, which zone may or may not be a treatment zone. Fluid-loss control refers to treatments designed to reduce such undesirable leakage. Providing effective fluid-loss control for well fluids during certain stages of well operations is usually highly desirable.
The usual approach to fluid-loss control is to substantially reduce the permeability of the matrix of the zone with a fluid-loss control material that blocks the permeability at or near the face of the rock matrix of the zone. For example, the fluid-loss control material may be a particulate that has a size selected to bridge and plug the pore throats of the matrix. All else being equal, the higher the concentration of the appropriately sized particulate, the faster bridging will occur. As the fluid phase carrying the fluid-loss control material leaks into the formation, the fluid-loss control material bridges the pore throats of the matrix of the formation and builds up on the surface of the borehole or fracture face or penetrates only a little into the matrix. The buildup of solid particulate or other fluid-loss control material on the walls of a wellbore or a fracture is referred to as a filter cake. Depending on the nature of a fluid phase and the filter cake, such a filter cake may help block the further loss of a fluid phase (referred to as a filtrate) into the subterranean formation. A fluid-loss control material is specifically designed to lower the volume of a filtrate that passes through a filter medium.
After application of a filter cake, however, it may be desirable to restore permeability into the formation. If the formation permeability of the desired producing zone is not restored, production levels from the formation can be significantly lower. Any filter cake or any solid or polymer filtration into the matrix of the zone resulting from a fluid-loss control treatment must be removed to restore the formation's permeability, preferably to at least its original level. This is often referred to as clean up.
A variety of fluid-loss control materials have been used and evaluated for fluid-loss control and clean-up, including foams, oil-soluble resins, acid-soluble solid particulates, graded salt slurries, linear viscoelastic polymers, and heavy metal-crosslinked polymers. Their respective comparative effects are well documented.
Fluid-loss control materials are sometimes used in drilling fluids or in treatments that have been developed to control fluid loss. A fluid-loss control pill is a treatment fluid that is designed or used to provide some degree of fluid-loss control. Through a combination of viscosity, solids bridging, and cake buildup on the porous rock, these pills oftentimes are able to substantially reduce the permeability of a zone of the subterranean formation to fluid loss. They also generally enhance filter-cake buildup on the face of the formation to inhibit fluid flow into the formation from the wellbore.
Fluid-loss control pills typically comprise an aqueous base fluid and a high concentration of a viscosifying agent (usually crosslinked), and sometimes, bridging particles, like graded sand, graded salt particulate, or sized calcium carbonate particulate.
Fluid Damage to Proppant Pack or Matrix Permeability
In well treatments using viscous well fluids, the material for increasing the viscosity of the fluid can damage the permeability of the proppant pack or the matrix of the subterranean formation. For example, a fracturing fluid can include a polymeric material that is deposited in the fracture or within the matrix. By way of another example, the fluid may include surfactants that leave unbroken micelles in the fracture or change the wettability of the formation in the region of the fracture.
Breakers are utilized in many treatments to mitigate fluid damage in the formation. However, breakers and other treatments are subject to variability of results, they add expense and complication to a fracture treatment, and in can still leave at least some fluid damage in the formation.
Breaker for Viscosity of Fluid
After a treatment fluid is placed where desired in the well and for the desired time, the fluid usually must be removed from the wellbore or the formation. For example, in the case of hydraulic fracturing, the fluid should be removed leaving the proppant in the fracture and without damaging the conductivity of the proppant bed. To accomplish this removal, the viscosity of the treatment fluid must be reduced to a very low viscosity, preferably near the viscosity of water, for optimal removal from the propped fracture. Similarly, when a viscosified fluid is used for gravel packing, the viscosified fluid must be removed from the gravel pack.
Reducing the viscosity of a viscosified treatment fluid is referred to as “breaking” the fluid. Chemicals used to reduce the viscosity of well fluids are called breakers.
No particular mechanism is necessarily implied by the term. For example, a breaker can reduce the molecular weight of a water-soluble polymer by cutting the long polymer chain. As the length of the polymer chain is cut, the viscosity of the fluid is reduced. For instance, reducing the guar polymer molecular weight to shorter chains having a molecular weight of about 10,000 converts the fluid to near water-thin viscosity. This process can occur independently of any crosslinking bonds existing between polymer chains.
Unfortunately, another complicating factor exists. Because of the large size of the polymer, a filtration process can occur upon the face of a formation or fracture in conventional formation. A filtercake of the polymer can be formed while the aqueous fluid, KCl, and breakers pass into the matrix of the formation. Careful examination of this filtercake, which may be formed from crosslinked or uncrosslinked guar or other polymer, reveals a semi-elastic, rubberlike membrane. Once the polymer concentrates, it is difficult to solubilize the polymer. Nonfiltercake fluid consists of approximately 99.5 percent water and 0.5 percent polymer. Accordingly, for example, when the fracture closes in a fracturing treatment, the permeability of the proppant bed or the formation face may be severely damaged by the polymer filtercake. Viscosified gravel pack fluids need breakers, too. They may or may not form a filtercake on the formation face.
Acidizing Treatment
A widely used stimulation technique is acidizing, in which a treatment fluid including an aqueous acid solution is introduced into the formation to dissolve acid-soluble materials. In this way, hydrocarbon fluids can more easily flow from the formation into the well. In addition, an acid treatment can facilitate the flow of injected treatment fluids from the well into the formation.
Acidizing techniques can be carried out as matrix acidizing procedures or as acid fracturing procedures.
In matrix acidizing, an acidizing fluid is injected from the well into the formation at a rate and pressure below the pressure sufficient to create a fracture in the formation. In sandstone formations, the acid primarily removes or dissolves acid soluble damage in the near wellbore region and is thus classically considered a damage removal technique and not a stimulation technique. In carbonate formations, the goal is to actually a stimulation treatment where in the acid forms conducted channels called wormholes in the formation rock. Greater details, methodology, and exceptions can be found in “Production Enhancement with Acid Stimulation” 2nd edition by Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, 66564-PA, and the references contained therein.
In acid fracturing, an acidizing fluid is pumped into a carbonate formation at a sufficient pressure to cause fracturing of the formation and creating differential (non-uniform) etching fracture conductivity. Greater details, methodology, and exceptions can be found in “Production Enhancement with Acid Stimulation” 2nd edition by Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, 66564-PA, and the references contained therein.